Method and apparatus for generating acoustic signal with single mode of propagation

ABSTRACT

A method and apparatus for generating an acoustic signal having a single mode of propagation along borehole walls. The method includes generating an n-pole (monopole, dipole, quadrupole, and so on) acoustic signal and calculating the tool position and borehole shape from the signals received at one or more receivers. If the tool contains matched sources and balanced receivers, is in the center of the borehole, and the borehole is circular, the pure, single mode acoustic signal will propagate along the borehole walls with a single mode of propagation. If the acoustic signal traveling along borehole walls does not have a single mode of propagation, the signal&#39;s amplitudes and time delays are adjusted to produce a second acoustic signal. The second acoustic signal&#39;s amplitudes and time delays are further adjusted until the signal traveling along the borehole walls has a single mode of propagation.

TECHNICAL FIELD OF THE INVENTION

The present invention relates to formation logging techniques. Moreparticularly, the present invention relates to a method and apparatusfor generating an n-pole (e.g. monopole, dipole, quadrupole, hexapoleand so on) acoustic signal with a single mode of propagation along thewalls of a borehole.

BACKGROUND OF THE INVENTION

Petroleum drilling and production operations require large quantities ofinformation relating to parameters and conditions downhole. Suchinformation typically includes characteristics of the earth formationstraversed by the wellbore, along with data relating to the size andconfiguration of the borehole itself. The collection of informationrelating to conditions downhole, which commonly is referred to as“logging,” can be performed by several techniques.

In conventional oil well wireline logging, a probe or “sonde” housingformation sensors is lowered into the borehole after some or all of thewell has been drilled, and is used to determine certain characteristicsof the formations traversed by the borehole. The upper end of the sondeis attached to a conductive wireline that suspends the sonde in theborehole. Power is transmitted to the sensors and instrumentation in thesonde through the conductive wireline. Similarly, the instrumentation inthe sonde communicates information to the surface by electrical signalstransmitted through the wireline.

The problem with obtaining downhole measurements via wireline is thatthe drilling assembly must be removed from the drilled borehole beforethe desired borehole information can be obtained. This can be bothtime-consuming and extremely costly, especially in situations where asubstantial portion of the well has been drilled. In this situation,thousands of feet of tubing may need to be removed and stacked on theplatform (if offshore). Typically, drilling rigs are rented by the dayat a substantial cost. Consequently, the cost of drilling a well isdirectly proportional to the time required to complete the drillingprocess. Removing thousands of feet of tubing to insert a wirelinelogging tool can be an expensive proposition.

As a result, there has been an increased emphasis on the collection ofdata during the drilling process. Collecting and processing data duringthe drilling process eliminates the necessity of removing the drillingassembly to insert a wireline logging tool. It consequently allows thedriller to make accurate modifications or corrections as needed tooptimize performance while minimizing down time. Designs for measuringconditions and formation properties downhole including the movement andlocation of the drilling assembly contemporaneously with the drilling ofthe well have come to be known as “logging-while-drilling” techniques,or “LWD.”

When oil wells or other boreholes are being drilled, it is frequentlynecessary or desirable to determine the direction and inclination of thedrill bit and downhole motor so that the assembly can be steered in thecorrect direction. Additionally, information may be required concerningthe nature of the strata being drilled, such as the formation'sresistivity, velocity, porosity, density and its measure of gammaradiation. It is also frequently desirable to know other downholeparameters, such as the temperature and the pressure at the base of theborehole, for example. Once this data is gathered at the bottom of theborehole, it is necessary to communicate it to the surface for use andanalysis by the driller.

In LWD systems, sources and receivers are typically located at the lowerend of the drill string. Typically, the downhole sources and receiversemployed in LWD applications are positioned in a cylindrical drillsection that is positioned close to the drill bit. As the drill bitprogresses through the formation, drilling noise, the noncircular shapeof the borehole, and the location of the logging tool in the boreholemay effect the collection of formation data. Each of the sources may beprogrammed to generate a pure n-pole acoustic signal with a single modeof propagation. Thus, n=1 is a monopole acoustic signal with monopolemode of propagation, n=2 dipole acoustic signal with dipole mode ofpropagation, n=4 quadrupole acoustic signal, n=6 hexapole acousticsignal, and so on. Acoustic signals generated by the sources travelthrough the borehole, and along the borehole walls of the formation orinto the formation depending on the velocity of the acoustic signal inthe formation (V_(f)) and the velocity of the acoustic signal in theborehole (V_(b)). Each type of n-pole acoustic signal permitsdetermination of different formation properties as described in moredetail below. If the borehole is not circular, the tool is not in thecenter of the borehole, the sources are mismatched (i.e., sources giventhe same input do not generate identical acoustic signals), or thereceivers are not balanced (i.e., receivers see identical acousticsignals at their inputs but generate varying electrical outputs for eachsignal), the signals at the receivers may have multiple modes ofpropagation (e.g., signal with both monopole mode and dipole modes ofpropagation). An acoustic signal with multiple modes of propagationarriving at the receivers interfere with each other and make thedetermination of formation properties inaccurate and difficult.

Thus, there is a continuing need for generating an n-pole acousticsignal with a single mode of propagation along the walls of the boreholethat compensates for drilling noise, noncircular imperfections in theshape of the borehole, and the location of the logging tool in theborehole.

SUMMARY OF THE INVENTION

According to an embodiment of the present invention, a method andlogging tool apparatus are provided for generating an acoustic signalhaving a single mode of propagation along borehole walls. The methodincludes generating an n-pole acoustic signal and calculating the toolposition and borehole shape from the signals received at one or morereceivers. The n-pole signal may be a monopole signal, dipole signal,quadrupole signal, or hexapole signal. If the tool contains sources thatcan generate a pure, single mode acoustic signal, balanced receivers, isin the center of the borehole, and the borehole is circular, theacoustic signal will propagate along the borehole walls with a singlemode of propagation. If the acoustic signal traveling along boreholewalls does not have a single mode of propagation, the signal'samplitudes and time delays are adjusted to produce a second acousticsignal. The second acoustic signal is generated from one or more toolsources. The second acoustic signal's amplitudes and time delays arefurther adjusted until the signal traveling along the borehole walls hasa single mode of propagation. The method includes generating theadjusted signal to determine hydrocarbon properties of the formation.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the embodiments of the invention,reference will now be made to the accompanying drawings in which:

FIG. 1 a is a schematic view of an LWD acoustic logging tool inaccordance with some embodiments of the invention located in a drillstring in a borehole, and a processing device at the surface;

FIG. 1 b shows a schematic view of the LWD acoustic logging tool inaccordance with some embodiments of the invention located in a deviatedborehole;

FIG. 2 is a graph of energy versus frequency showing the drilling noiseand propagation modes for each n-pole signal source;

FIG. 3 is a more detailed schematic view of the acoustic logging tool inaccordance with some embodiments of the invention shown in FIGS. 1 a and1 b;

FIG. 4 is a top view of the borehole showing the acoustic logging tooloff-center in a non-circular borehole;

FIG. 5 a is a cross-sectional view of the acoustic signal pattern in theborehole and along the borehole walls generated by monopole sources inthe logging tool;

FIG. 5 b is a cross-sectional view of the acoustic signal pattern in theborehole and along the borehole walls generated by dipole sources in thelogging tool;

FIG. 5 c is a cross-sectional view of the acoustic signal pattern in theborehole and along the borehole walls generated by quadrupole sources inthe logging tool;

FIG. 5 d is a cross-sectional view of the acoustic signal pattern in theborehole and along the borehole walls produced by generalized n-polesources in the logging tool;

FIG. 6 a shows a block diagram of the processing hardware in the tooland on the surface in accordance with some embodiments of the invention;

FIG. 6 b shows in accordance with other embodiments of the invention ablock diagram of the processing hardware in the tool and on the surface;

FIG. 7 shows a flow chart of an illustrative technique for generating anacoustic signal with a single mode of propagation that may beimplemented by the system of FIG. 6 a or FIG. 6 b;

FIG. 8 shows a schematic of control electronics for the monopole source;and

FIG. 9 shows a schematic of control electronics for a dipole source.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood, however, that the drawings and detaileddescription thereto are not intended to limit the invention to theparticular form disclosed, but on the contrary, the intention is tocover all modifications, equivalents and alternatives falling within thespirit and scope of the present invention as defined by the appendedclaims.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and claimsto refer to particular system components and configurations. As oneskilled in the art will appreciate, companies may refer to a componentby different names. This document does not intend to distinguish betweencomponents that differ in name but not function. In the followingdiscussion and in the claims, the terms “including” and “comprising” areused in an open-ended fashion, and thus should be interpreted to mean“including, but not limited to . . . ”. Also, the term “couple” or“couples” is intended to mean either an indirect or direct electricalconnection. Thus, if a first device couples to a second device, thatconnection may be through a direct electrical connection, or through anindirect electrical connection via other devices and connections. Theterms upstream and downstream refer generally, in the context of thisdisclosure, to the transmission of information from subsurface equipmentto surface equipment, and from surface equipment to subsurfaceequipment, respectively. Additionally, the terms surface and subsurfaceare relative terms. The fact that a particular piece of hardware isdescribed as being on the surface does not necessarily mean it must bephysically above the surface of the earth; but rather, describes onlythe relative placement of the surface and subsurface pieces ofequipment.

DETAILED DESCRIPTION OF EMBODIMENTS

FIG. 1 a shows a well during drilling operations. A drilling platform 2is equipped with a derrick 4 that supports a hoist 6. Drilling of oiland gas wells is carried out by a string of drill pipes connectedtogether by “tool” joints 7 so as to form a drill string 8. The hoist 6suspends a kelly 10 that is used to lower the drill string 8 throughrotary table 12. Connected to the lower end of the drill string 8 is adrill bit 14. The bit 14 is rotated and drilling accomplished byrotating the drill string 8, or by use of a downhole motor near thedrill bit, or by both methods. Drilling fluid, termed mud, is pumped bymud recirculation equipment 16 through supply pipe 18, through drillingkelly 10, and down through the drill string 8 at high pressures andvolumes to emerge through nozzles or jets in the drill bit 14. The mudthen travels back up the hole via the annulus formed between theexterior of the drill string 8 and the borehole wall 20, through ablowout preventer (not specifically shown), and into a mud pit 24 on thesurface. On the surface, the drilling mud is cleaned and thenrecirculated by recirculation equipment 16. The drilling mud is used tocool the drill bit 14, to carry cuttings from the base of the bore tothe surface, and to balance the hydrostatic pressure in the rockformations. However, the system of FIG. 1 a is not restricted to the useof mud as a drilling fluid. For example, in the case of under balanceddrilling (UBD), other media such as aerated fluids or air/mist mixturesmay be preferred over mud.

The acoustic logging tool shown in FIGS. 1 a and 1 b may haveprogrammable sources that allow the tool to generate monopole (n=1),dipole (n=2), quadrupole (n=4), hexapole (n=6) or any other n-pole (forn being an even number) signals. Each kind of n-pole signal providesdifferent sets of data that may be used to determine properties of theformation. Thus, for example, monopole sources may be used to generate amonopole mode of propagation along borehole walls for determining thevelocities of compressional and shear waves. To confirm the accuracy ofthe compressional and shear wave velocities, the logging tool mayinclude dipole sources for generating dipole mode of propagation alongborehole walls. The dipole source can produce a different data set thatmay independently be used to determine the velocities of compressionaland shear waves. A quadrupole source may be used to determine formationproperties during logging when modes of propagation through the tool areinterfering with collection of data. Monopole and dipole sources maycreate modes of propagation through the tool even if the tool hasisolators at the source and receiver ends and in between the source andreceiver (described in more detail below). Acoustic sources generatingquadrupole signals reduce tool modes because the tool modes of thequadrupole signal cancel each other as they travel through the loggingtool.

In accordance with some embodiments of the invention, programmablesources in LWD acoustic logging tool 40 shown in FIG. 1 a located indrill string 8 produce an acoustic signal with a single mode ofpropagation along borehole walls 20. Receivers located in the LWDacoustic logging tool receive signals traveling through the borehole,formation, and along the borehole walls. In some embodiments of theinvention, the received signals are processed by processing circuitry inthe logging tool to determine the amplitudes and time delays for thesource signal so that a single mode of propagation is excited along theborehole walls. Formation data determined from the received signals issent to the surface where it is transmitted through communicationinterface 42 and communication link 44 to computer system 46. In someembodiments, communication link 44 may be a telephone cable or awireless connection to computer system 46. Computer system 46 includes acentral processing unit (CPU) 47 coupled to a viewing device 48 that,preferably, may be a computer display screen to view the logging dataand input device 50 that, preferably, may be a computer keyboard.

In some embodiments of the invention, preliminary filtering andamplification of the received signal may be performed in the processingcircuitry of the acoustic logging tool. Further processing to determinethe source signal amplitudes and time delays so that a single mode ofpropagation is excited along the borehole walls may be done by computersystem 46. Thus, the processing circuitry may be reduced in cost andcomplexity because it is used only for filtering and amplification ofthe received signal.

FIG. 1 b shows the LWD acoustic logging tool in the drill stringdeviated towards the right 60 in the borehole. In some embodiments ofthe invention, the LWD acoustic logging tool may not have mechanicalcentralizer fins or may have very small fins for keeping the tool in thecenter of the borehole. In the logging while drilling environment,mechanical centralizers may cause interference in collection of loggingdata. For some embodiments of the invention, mechanical centralizers mayinterfere with generation of a single mode of propagation along boreholewalls.

Without mechanical centralizers, the acoustic logging tool may not be inthe center of the borehole as shown in FIG. 1 b because the borehole isdeviated. In some drilling situations, to reach hydrocarbon deposits inhard to reach sections of the formation, the drill string and acousticlogging tool may be in a horizontal borehole. The off-center location ofthe tool in the borehole interferes with collection of logging databecause acoustic sources are not able to generate a signal with a singlemode of propagation along borehole walls.

As shown in FIG. 1 b, the borehole walls in sections 62 and 64 may notbe uniformly circular. The noncircular shape of the borehole can alsointerfere with the acoustic sources ability to generate a signal with asingle mode of propagation along the borehole walls.

Turning to FIG. 2, the affects of drilling noise 205 on acoustic signalswith an n-pole mode of propagation is shown. Conventional drilling noise205 appears with the n-pole signal in the energy-frequency graph becausethe acoustic tool is logging as the drill bit drills the borehole. Theenergy-frequency graph shows the energy of the drilling noise and modeof propagation for each n-pole signal source over a range offrequencies. The drilling noise is attenuated at approximately 5Kilohertz (KHz) 205 but interferes with the monopole 210, dipole 220,and quadrupole 230 propagation modes in the borehole below 5 KHz.Interference by the drilling noise may result in the monopole, dipole,and quadrupole modes of propagation becoming distorted as they travelalong the borehole walls because the noise adds and subtracts from thepropagation modes. Hexapole 240 and higher n-pole modes (not shown inFIG. 2) of propagation are not affected as much by the drilling noise asthe monopole, dipole, and quadrupole modes of propagation. Filtering ofthe drilling noise 205 from the propagation mode signals is noteffective because it filters out information at the frequencies of thedrilling noise that includes the monopole, dipole, and quadrupole modesas shown in FIG. 2. To correctly receive data for propagation modes thatare affected by drilling noise, the amplitude and time delays of thesource signal may be modified as described below so that the propagationmode signal along borehole walls has minimal noise.

FIG. 2 also shows how each n-pole acoustic signal may be used todetermine different formation properties. Low frequency acoustic signalstravel through the formation while high frequency acoustic signalsgenerally travel in the mud and water in the borehole. Thus, for a lowfrequency signal, the receivers receive a waveform that has traveledmostly through the formation. The velocity of propagation in theformation V_(f) may therefore be determined by generating a lowfrequency monopole signal at less than 5 KHz as shown in FIG. 2. Thevelocity of propagation in the borehole mud and water V_(b) may bedetermined by generating a high frequency f_(d) dipole signal 225.Verification of V_(b) may be performed by generating a very highfrequency f_(m) monopole signal 245 as shown in FIG. 2.

Noise caused by drilling of the borehole as the acoustic tool islogging, the noncircular nature of the borehole, and the acoustic toollocated off-center in the borehole may result in the signal along theborehole walls not having a single mode of propagation. For example, ifthe sources generate monopole mode signals, the interference may resultin monopole, dipole, and quadrupole modes excited along the boreholewall and received at the receivers. Separating out data sets from themultiple mode arrivals may not be possible or inaccurate, resulting inincorrect formation properties.

FIG. 3 shows the LWD acoustic logging tool 300 in more detail inaccordance with some embodiments of the invention for the drill stringshown in FIGS. 1 a and 1 b. Preferably, electronics section 310 maycontain the processing circuitry shown in FIG. 6 a or 6 b that controlsthe sources 320 in the tool 300 and processes the signal from thereceivers 340. Electronics section 310 may send information to thecommunication interface 42 located on the surface by using a phase-shiftkey (PSK) data transmission system. In the PSK transmission system,decreasing the carrier frequency provides a stronger signal at the riskof aliasing, especially with wide bandwidth signals. However, thecarrier frequency may be decreased while increasing the number of phasestates to achieve a higher data rate, without affecting the bandwidth.The PSK data transmission system provides a robust, low-powerelectromagnetic telemetry system with an increased data rate.

In some embodiments of the invention, electronics section 310 enablesthe operation of the acoustic logging tool by controlling the triggeringand timing of the acoustic sources. A controller in the electronicssection 310 fires the acoustic sources periodically, thereby producingacoustic pressure waves that propagate through the borehole fluid andinto the surrounding formation. At the borehole boundary, some of theacoustic energy is converted into compressional waves that travelthrough the formation, and into shear waves that propagate along theinterface between the borehole fluid and the formation. As these wavespropagate past the receiver array 350, they cause pressure variationsthat can be detected by the receiver array elements. Preferably, thereceiver array signals are processed in the digital signal processor(DSP) circuitry 628 shown in FIG. 6 a or 6 b to determine the formationcharacteristics. In some other embodiments of the invention, thereceiver array signals are processed on the surface in computer system46 to determine the formation characteristics.

The source section 320 includes a monopole source 323 and a pair ofcrossed-dipole sources 326. The monopole source 323 includes apiezoelectric crystal of cylindrical geometry. The crystal is mounted inan arrangement that allows the transmitted acoustic energy to beessentially uniform around the circumference of the tool. The monopolesource is energized in the typical ‘pulsed’ mode (described below withreference to FIG. 8), where an essentially pure monopole mode wave isemitted with a center frequency around 5-6 kHz and energy throughout thefrequency band between 1 kHz and 12 kHz. This center frequency isbetween approximately a third and a half of the monopole sourcefrequency of traditional monopole tools. The lower frequency results ina much greater depth of investigation for the compressional wave andrefracted shear wave. The monopole source is utilized for derivation ofthe refracted arrivals from the full wave acquisition, i.e. thecompressional wave velocity (as well as other associated properties suchas energy, frequency content, etc.), the refracted shear wave velocityand its associated wave properties, and the Stoneley wave velocity withits own associated parameters.

Each of the dipole sources 326 includes two transducers mounted onopposite sides of the tool 300. The crossed dipoles are mountedperpendicularly, so that together, the crossed dipoles form an on-depthquad arrangement of transducers. Each of the four dipole sourcetransducers are preferably of the “bender bar” type, i.e. a flexiblesurface having piezoelectric crystals on opposing sides. As the crystalon one side is driven to elongate, the crystal on the opposite side isdriven to shrink. This causes the assembly to flex. Acoustic signals aretransmitted by flexing the surface at the desired frequencies. Thesignal frequency is programmable, as described below, but the sourcetransducers are preferably capable of signal frequencies between atleast 0.5 kHz to 3 kHz.

The orthogonal positioning of the bender bar sources allows for acontrolled X—X and Y—Y flexural wave generation. The sources are mountedin a way such that very little energy is coupled into the tool housingassembly, thus minimizing the excitation of unwanted acoustic waves inthe tool itself. In addition, the source mounting ensures that there isno cross-excitation from one pair of the bender bars to the other, thusensuring a proper acoustic dipole signature.

Isolator section 330 in FIG. 3 contains an acoustic isolation component.The acoustic isolator serves to attenuate and delay acoustic waves thatpropagate through the body of the tool from the sources 320 to thereceiver array 340. Any standard acoustic isolator may be used.Preferably, the acoustic isolator can withstand 100,000 pounds force ofpush or pull, and provides for more than 90 dB of acoustic isolationover an extended frequency range, extending as low as about 500 Hz to600 Hz.

In addition to the main isolator 330, additional acoustic waveisolators/absorbers are preferably placed on the receiver section bothat the ends and between successive receiver sets (not shown in FIG. 3).Finally, the mounting of the dipole sources and the receivers themselvesprovides further isolation. The combination of all of the above allowsthe acoustic logging tool to properly acquire formation acoustic signalsin the sub-kilohertz region, a region that is very close to the limitfor the excitation of flexural waves. (The excitation function for theflexural waves exhibits a dramatic drop as the source frequency isreduced to the area of 600 Hz to 1 kHz; source operating frequenciesbelow that level will excite predominantly tube waves with very little,if any, flexural wave components.)

Configuration of the sources in the manner described and shown in FIG. 3allows generation of a monopole mode as shown in FIG. 5A by the monopolesources and generation of a dipole mode as shown in FIG. 5B by thedipole sources. In one embodiment of the invention, acoustic loggingtool 300 also contains a receiver array 340 that consists of 16 receivercrystals arranged in four co-planar rings 350 a-350 d. In some otherembodiments of the invention, the receiver array 340 consists of 32receiver crystals arranged in eight co-planar rings. Each ring has fourreceivers mounted perpendicular to the tool axis and evenly distributedat 90 degrees from each other. The circumferential positioning of thereceivers is preferably aligned with the dipole sources so that thereare two in-line arrays and two cross-line arrays for both the X—X andY—Y dipole sources. In the dipole acquisition mode, the in-line receiverarray and the cross-line receiver array are each 2 by 8 arrangements ofreceivers.

In some embodiments, the receivers have a frequency response from 0.5kHz to about 20 kHz. The 16 individual receivers are mounted in receiverpockets, slightly indented from the external surface of the toolhousing. Each receiver is individually pressure and temperaturecompensated to the full extent of the operating specifications for thetool (e.g., 20,000 psi, 175 degrees Celsius). This allows for easywellsite maintenance if one of the receivers is damaged for any reason,without the need for elaborate oil filling or evacuation stations.

Preferably, the acoustic sources 320 and receiver array 340 are based onpiezoelectric elements designed to operate in downhole conditions.However, many other sources and detectors are suitable for downholeoperation, and may be used.

Receivers in co-planar rings 350 a-350 d allow determination of thearrival times and velocities of acoustic signals traveling in theborehole, in the formation, and along the formation walls. Monopole modewaves first arrive at receiver ring 350 a and then the same waveformarrives at receiver ring 350 b after a time t (t is time needed forwaveform to travel distance from receiver ring 350 a to receiver ring350 b). Since the distance between the receiver rings is known, thevelocity of the waveform in the formation V_(f) and along the boreholewalls V_(b) can be determined by using the time t. As mentioned above,in alternative embodiments, eight levels of receiver arrays may bepresent allowing measurement of the velocity of large wavelengthsignals.

FIG. 4 illustrates a top view of a cross-section of a non-circularborehole 410 with the acoustic logging tool 40 off-center in theborehole. Borehole cross-section 410 may be from a deviated orhorizontal borehole as shown in FIG. 1 b, making the acoustic loggingtool 40 lean to one side. Thus, the center of the tool may be located atpoint 440 and the approximate center of borehole 410 may be at point430. The drill bit attached to the drill string may cause indentation425 in the borehole wall, making the borehole cross sectionnon-circular. Thus, an n-pole source may not generate an n-pole mode ofpropagation along borehole walls because the borehole is not circularand the tool is not in the center of the borehole as shown in FIG. 4.

Receivers at the same level receive the acoustic signal at approximatelythe same time if the tool is centered in the borehole and the boreholeis circular. If, as shown in FIG. 4, the tool is not in the center ofthe borehole and the borehole is not circular, receivers at the samelevel will not receive the acoustic signal at the same time. This isbecause a signal generated by the source closer to the borehole wall inlogging tool 40 has less distance to travel to the receivers close tothe borehole wall. The reflected signals from the borehole walls on theside of the tool that is the greatest distance from the wall must travela larger distance to reach the wall and return to the receivers in thetool. Stacking the signals for receivers at the same level will show ifall of the signals have arrived at the same time. A signal arrivingsooner than the other signals indicates receivers in the tool closer tothe wall and the appropriate delay may be programmed into the receivers.

If the tool is not in the center of the borehole or the borehole is notcircular as shown in FIG. 4, the amplitude of the signals from theacoustic sources will not be the same along the walls of the borehole.Because of the properties of the borehole mud, acoustic signals areattenuated as they travel through the mud. The signals generated bysources farther away from the borehole wall are more attenuated thansignals generated by sources closer to the wall. This is because signalsfrom farther sources must travel a larger distance through the mud toreach the wall. Thus, the acoustic signals generated by the sourcesclosest to the borehole wall will have larger amplitudes along theborehole walls compared to the signals generated by sources farthestfrom the borehole walls. The signal amplitudes should be the same for ann-pole signal with a single mode of propagation along the boreholewalls. Thus, if the tool is not in the center of the borehole or theborehole is not circular, the amplitudes received by the receivers willnot be the same. A received signal with smaller amplitude indicatessources in the tool farther from the borehole wall; the amplitude levelfrom the source may be increased to compensate for the attenuation andproduce a signal with a single mode of propagation along the boreholewalls.

Referring to FIGS. 5 a-5 d, these figures show cross-sections of theacoustic waveform pattern for monopole, dipole, quadrupole and n-polesignals, respectively, in the borehole 500 and along the borehole walls410. In FIG. 5 a, the monopole waveform pattern radiates sound equallyin all directions and may be modeled as the cross section of a spherewhose radius alternately expands and contracts sinusoidally.

FIG. 5 b shows a cross-section of the dipole signal in the borehole andalong the borehole walls. The dipole waveform pattern may be consideredtwo monopole waveforms of equal strength but opposite phase andseparated by a small distance compared with the wavelength of sound.While one monopole waveform expands the other monopole waveformcontracts. The dipole waveform pattern may be modeled as a sphere whichoscillates back and forth, that is while the front is pushing outwardsthe back is sucking inwards. A dipole waveform pattern does not radiatesound equally in all directions. The waveform pattern appears like afigure eight-there are two regions 503 and 505 where sound is radiatedvery well, and two regions 507 and 510 where sound cancels.

FIG. 5 c shows a cross-section of the quadrupole signal in the boreholeand along the borehole walls. The quadrupole waveform pattern may beconsidered as two opposite dipole waveform patterns. The two dipolewaveforms do not lie along the same line, that is they may be modeled asfour monopoles with alternating phase at the corners of a square. Thus,the waveform pattern for quadrupole signal looks like a clover leafpattern-sound is radiated well in front of each monopole “leaf” 520,525, 530, and 535, but sound is canceled at points 522, 527, 532, and537 equidistant from adjacent opposite monopole “leaves.”

Finally, referring to FIG. 5 d, a cross-section of the n-pole signal inthe borehole and along the borehole walls is shown. The n-pole signal isthe generalized waveform pattern for dipole signal, quadrupole signal,hexapole signal, octapole signal and so on. The n-pole waveform patternmay be considered as n/2 opposite dipole waveform patterns. The n/2dipole waveform patterns do not lie along the same line, that is theymay be modeled as n monopoles with alternating phase at the corners ofan n-sided polygon. Thus, the waveform pattern for a generalized n-polesignal looks like a clover leaf pattern-sound is radiated well in frontof each monopole “leaf” 540, 545, 550, 555, 560, 565 and 570, but soundis canceled at points 541, 542, 547, 552, 557, 562, 563 and 567equidistant from adjacent opposite monopole “leaves.”

Turning now to FIG. 6 a, a block diagram of the processing hardware inthe tool and on the surface in accordance with some embodiments of theinvention is shown. A number of receivers 602, 604, 606 are each coupledto an analog-to-digital converter (ADC) 616, 618, 620, respectively. TheADCs convert the analog acoustic signals to digital binary bits.

Digital signal processor (DSP) 628 may process the received digitalacoustic signals to determine a time delay associated with any acousticsignal reflections. As part of the processing, DSP 628 may applyvariable gain to compensate for attenuation, cross-correlate the receivesignals with a signal model, and distinguish primary borehole wallreflections from secondary reflections and “false” reflections caused bybubbles or debris. DSP 628 may further collect orientation measurementsfrom an azimuth sensor (not shown) and associate each time delay with anazimuth value.

Each time delay may be converted into a distance measurement, and thedistance measurements may be combined to determine borehole shape andsize, along with tool position in the borehole. Statistics on boreholediameter, tool offset, and tool motion may also be calculated. Theconversion and combining may be performed downhole by DSP 628, or someof the processing may be performed on the surface. In any event, thetime delay and azimuth measurements (and/or processed data) may beprovided to a downhole modem 635 for transmission via a telemetrychannel 695 to a surface modem 638. A processor 642 collects theinformation, and stores the information in memory 640 and/or anonvolatile information storage device (not shown). The processor 642may also execute software in memory 640. As shown in FIG. 1 a, CPU 47may include modem 638, memory 640, and processor 642. The software mayconfigure processor 642 to interact with a user via an output device 660and an input device 644. Output device 660 may be a computer displayscreen 48 and the input device 644 may be a computer keyboard 50 asshown in FIG. 1 a. The user may be provided with a prompt and/or one ormore options on output device 660, and may respond with commands viainput device 644. In response to such input, the software may configurethe processor 642 to process the information collected from downhole andpresent the results to the user in graphical fashion.

DSP 628 determines acoustic signals encoded in digital binary bits andsends the binary encoded acoustic signals to digital-to-analog converter(DAC) 622, 624 that convert the signals into analog signals forgeneration by sources 608, 609. DSP 628 may execute software or firmwarethat implements the flowchart shown in FIG. 7 (described in greaterdetail below) to produce an acoustic signal having a single mode ofpropagation along borehole walls. In alternative embodiments of theinvention, processor 642 may execute software that implements theflowchart of FIG. 7 and DSP 628 may perform the functions as describedin the paragraphs above. Receivers 602, 604, 606 receive the acousticsignal generated by the sources 608, 609 after the signals have traveledthrough the formation, borehole and along the borehole walls. Using theacoustic signal velocity in the borehole as shown in FIG. 7, the DSP 628adjusts the acoustic signal so that the acoustic signal has a singlemode of propagation along the borehole walls. The acoustic signalvelocity in the borehole is determined from acoustic signal velocitysensor 626.

In some other embodiments of the invention shown in FIG. 6 b, a numberof acoustic transceivers 670, 672, 674 that can function as both sourceand receiver are coupled to a transceiver control switch 678. Thetransceiver control switch 678 configures the transceivers to operate inone of multiple arrangements. In a receive arrangement, the transceivercontrol switch 678 couples each of the transceivers 670, 672, 674 to arespective ADC 680, 682, 684. In a transmit arrangement, the transceivercontrol switch 678 couples a selected one of the transceivers 670, 672,or 674 to DAC 686, and isolates all transceivers 670, 672, 674 fromtheir respective ADCs 680, 682, 684. The transceiver control switch 678operates under control of DSP 628.

DSP 628 controls the transmission of acoustic signals and the receptionof acoustic signal reflections. As part of the transmission process, DSP628 may select an individual transceiver to be coupled to DAC 686. DSP628 may then provide a signal to the transceiver via the DAC 686. Aspart of the receive process, DSP 628 may operate transceiver controlswitch 678 to couple each transceiver to a respective ADC. DSP 628 maythen store the received signals in memory 630.

Turning now to FIG. 7, a flow chart of a technique for generating anacoustic signal with a single mode of propagation that may beimplemented by the systems of FIG. 6 a or FIG. 6 b is shown. Asmentioned above, the technique for generating an acoustic signal with asingle mode of propagation may be implemented in software or firmwareand executed by the DSP 628 or processor 642. In some embodiments of theinvention, firmware implementing the technique shown in FIG. 7 may bepresent in memory 630 that may contain non-volatile electronicallyprogrammable read-only-memory (EPROM). Alternatively in some otherembodiments, the software implementing FIG. 7 may be stored on acomputer readable medium (not shown in FIG. 6 a or 6 b) for execution byprocessor 642.

The technique of FIG. 7 will be described with reference to FIG. 6 a'sconfiguration of source and receivers. An n-pole acoustic signal withn=1 (monopole), 2 (dipole), 4 (quadrupole) and so on for any even numbern is produced in 710 by firing the sources 608, 609. In 720, theposition of the acoustic logging tool in the borehole and shape of theborehole is determined using the acoustic signal received at receivers602, 604, 606 and the acoustic signal velocity from block 740.Calculation of the tool position and borehole shape, as described above,includes the DSP processing the received digital acoustic signals todetermine a time delay. Each time delay may be converted into a distancemeasurement, and the distance measurements may be combined to determineborehole shape, along with tool position within the borehole. Next, inblock 730, the DSP determines if the signal along the borehole wallshave a single mode of propagation. If the acoustic logging tool is inthe center of the borehole and the borehole is circular as calculated inblock 720, then the signal along the borehole walls will contain asingle mode of propagation. Alternatively, another technique todetermine if the signal along the borehole walls has a single mode ofpropagation is to cross-correlate the signal from the receivers with aknown signal model of the n-pole (monopole, dipole, and so on) signal.If the signal along the borehole walls has a single mode of propagation,then the sources generate the acoustic signal in block 770 that is thesame as the signal generated in block 710. If the signal along theborehole walls does not have a single mode of propagation, then in block750 the time delays and amplitudes of pulses for the sources iscalculated such that the signal along the borehole walls has a singlemode of propagation. Determination of time delays and amplitudes for theacoustic signal pulses are described with reference to FIG. 4 above.

As described below, the velocity of the acoustic signal in the boreholefluid in 740 may be needed to calculate the time delays and amplitudesof signal pulses for the sources. In accordance with one embodiment, theacoustic impedance of the borehole fluid may be found using reflectionsfrom a precise metal disk, and therefrom the density of the boreholefluid. Because the reverberation characteristics of an acoustic wavedepend in part on the acoustic wave shape, the first reflection from themetal disk may be used to calibrate the measurement. A technique fordetermining a velocity of the acoustic signal in the borehole fluidincludes generating an acoustic signal within the borehole fluid,receiving reflections of the acoustic signal from the fluid, andanalyzing a reverberation portion of the acoustic signal to determinethe velocity. Analyzing the reverberation portion may include obtaininga theoretical reverberation signal and relating the measuredreverberation signal with the theoretical reverberation signal todetermine the velocity of the acoustic signal in the borehole fluid. Thereceiver sees a waveform consisting of a loud initial reflectionfollowed by an exponentially decaying reverberation signal. If time t=0is the time of generation of the acoustic wave at the source, then thetime T_(tran) represents the transit time (the time for the travel ofthis acoustic wave to the metal disk and to the receiver). Since thedistance is fixed and known, the transit time T_(ran), provides anindication of the acoustic signal velocity in the fluid.

In 760, acoustic signal pulses with the determined time delays andamplitudes are created. The time delayed and amplitude adjusted acousticsignal is generated as shown in block 770 by driving the sources withthe appropriate signal pulses. FIG. 8 provides a schematic for thecontrol electronics of the monopole source. These control electronicsare more-or-less representative of existing acoustic tools. The monopolesource 323 is coupled to the secondary winding of a step-up transformer804. (A tuning inductance 840 is commonly included to lower the resonantfrequency of the signal.) The primary winding of transformer 804 iscoupled to a capacitor 810, and a transistor 808 momentarily closes thecurrent loop between the primary winding and the capacitor 810. Whentransistor 808 is off, the capacitor 810 is charged by a voltage sourcevia a resistance 812 (or a transistor or other current-limiting means).

Transistor 808 is controlled by a controller 628. To “fire” the monopolesource, the controller 628 asserts a control signal that turnstransistor 808 on, thereby allowing capacitor 810 to discharge throughthe primary winding of transformer 804. This causes an oscillatorycurrent in the secondary winding. This oscillatory current is anelectrical signal that causes monopole source 323 to generate anacoustic signal.

In some embodiments, controller 628 is a DSP (FIGS. 6 a-6 b) thatexecutes software stored in an attached memory 630. The controller 628may be coupled to an uphole communications module 635 (FIG. 6 a-6 bmodem 635) via a tool bus 833. A surface computer 47 (FIG. 1 a) cancommunicate with the controller 628 to read and change operatingparameters of the controller 628 and of the software algorithms. Themonopole source is fully programmable in all its aspects includingfrequency, amplitude, emitted wave signature, and wave duration. Inaddition to the programmability of the dipole source characteristics,the electronics in the tool offer almost limitless control of the source“firing” sequence and the timing between consecutive firings.

FIG. 9 provides a schematic for the control electronics for a dipolesource. Unlike that of the monopole source, the drive circuits for thedipole source employ a linear driver configuration. Accordingly, theacoustic signal generated by source 326 closely tracks the analog signalgenerated by DAC 622 in response to a digital waveform provided bycontroller 628. The waveform may be stored in memory 630 or may begenerated in accordance with the software stored therein. In analternative embodiment, the waveform may be transmitted from thesurface.

Dipole source 326 converts an electrical signal into an acoustic signalthrough voltage-induced expansion and contraction. The expansion andcontraction of source 326 are respectively caused by positive andnegative voltage differences across the terminals. Positive voltagedifferences are induced in the secondary winding of transformer 905 whentransistor 909 turns on and transistor 911 is off. Conversely, negativevoltage differences are induced when transistor 911 turns on andtransistor 909 is off. The control signals for transistors 909, 911 areprovided from a rectifier/splitter module 916 via amplifiers 913, 915.

The rectifier/splitter module 916 splits an input signal into two outputsignals. One of the output signals represents the input signal when theinput signal is positive, and equals zero when the input signal isnegative. The other output signal represents the negative of the inputsignal when the input signal is negative, and equals zero when the inputsignal is positive. Thus, both output signals are always positive orzero.

The remaining portion of the control electronics for the dipole sourceis summing amplifier 918. The output of summing amplifier 918 isprovided as the input signal to rectifier/splitter module 916. Thesumming amplifier has a non-inverting input, which is grounded, and aninverting input, which receives a weighted sum of four signals: theanalog signal from DAC 622, the output of summing amplifier 918, and thevoltages on the outer terminals of the primary winding of transform 905.Each of the four signals is provided to the inverting input of summingamplifier 918 via a corresponding resistance 919, 920, 922, 924. Therelative weights of resistances 919-924 are selected to cause thevoltages on the outer terminals of the primary winding to track theirrespective portions of the analog signal as closely as possible. Thisdesign permits the use of high-power rated MOSFET transistors (which aretypically nonlinear devices) in a high-power linear amplifier.

The programmability of the acoustic logging tool makes possible avariety of improved logging methods. In one improved logging method, thecontroller 628 may be programmed with a dipole waveform that maximizesthe signal energy while minimizing the tool mode. That is, theprogrammed waveform may be a broadband signal with frequency nulls atvibration modes of the tool body.

Other parameters that are preferably programmable include: the firingrate, the digitizing interval (i.e. the sampling frequency of the A/Dconverter), and the number of samples acquired by each sensor.

For each of the improved logging methods, the adjusted parameters may becontrolled from the surface, either automatically or by manual control;or they may be controlled by the tool itself (e.g. using adaptivecontrol mechanisms or algorithms).

The acoustic logging tool is fully combinable with all logging suites,thus minimizing the number of logging trips required for formationevaluation. The low frequency monopole source (compared to other fullwaveform and dipole sonic tools) allows the compressional and shear wavevelocity measurements to be obtained within similar depths ofinvestigation, well beyond any near-wellbore altered region. And lastly,the on-depth crossed dipole sources and transmitter firing sequence,allows for all 16 dipole waveforms from the four level receiver array tobe reliably used for anisotropy analysis without the need of depthshifting, or normalization of waveform data.

Returning to FIG. 7, acoustic signals after traveling through theformation, borehole, and along the borehole walls are received at thereceivers as shown in block 780. If the wavefield along the boreholewall is not the appropriate mode of propagation, then the time delaysand amplitudes of the pulses are recalculated in block 750 and generatedby the sources. The loop from block 790 to block 750 is performed untilthe wavefield along the borehole wall is the appropriate mode ofpropagation. Acoustic logging of the formation around the tool in theborehole is performed once the wavefield along the borehole wall has asingle mode of propagation. The tool continues logging as the drill bitprogresses through the formation. As the logging tool is lowered intothe next section of the borehole, the technique of FIG. 7 is restartedfrom block 710 to determine if the next borehole section is circular andthe tool is in the center of the borehole.

While the present invention has been described with respect to a limitednumber of embodiments, those skilled in the art will appreciate numerousmodifications and variations therefrom. It is intended that the appendedclaims cover all such modifications and variations as fall within thetrue spirit and scope of this present invention.

1. A method for generating an acoustic signal with a single mode ofpropagation along borehole walls, comprising: adjusting a first signal'samplitudes and time delays to produce a second signal if the firstsignal traveling along borehole walls does not have a single mode ofpropagation; generating the second signal from one or more tool sources;receiving the second signal at one or more receivers; and modifying thesecond signal's amplitudes and time delays if the second signaltraveling along the borehole walls does not have the single mode ofpropagation.
 2. The method of claim 1, further comprising: determine ifthe tool is in center of the borehole and the borehole is circular; andgenerating an n-pole signal from the one or more tool sources if thefirst signal traveling along borehole walls has a single mode ofpropagation.
 3. The method of claim 2, wherein amplitudes and timedelays of the first signal are adjusted if the tool is not centered inthe borehole or the borehole is not circular.
 4. The method of claim 2,wherein amplitudes and time delays of the first signal are adjusted ifthe sources are not matched or the receivers are not balanced.
 5. Themethod of claim 2, wherein the n-pole signal is from the groupconsisting essentially of a monopole signal, dipole signal, quadrupolesignal and hexapole signal.
 6. The method of claim 2, whereindetermining if the tool is in the center of the borehole and theborehole is circular comprises calculating position of the tool in theborehole and shape of the borehole from signals received at the one ormore receivers.
 7. The method of claim 2, wherein the legging toolcouples to a drilling device that drills the borehole as the toolgenerates the signal with a single mode of propagation along theborehole walls.
 8. The method of claim 1, wherein determining timedelays and amplitudes of the signals includes determining velocity ofthe signal in the borehole.
 9. A logging tool to generate an acousticsignal in a borehole, comprising: one or more sources capable ofgenerating a first signal; one or more receivers capable of receivingthe first signal traveling along the borehole walls; and a processingdevice that couples to the sources and receivers, said processing devicecapable of adjusting the first signal's amplitudes and time delays toproduce a second signal if the signal traveling along the borehole wallsdoes not have a single mode of propagation, the one or more sourcesgenerating the second signal.
 10. The logging tool of claim 9, furthercomprising: a computer system that couples to the processing device,said computer system capable of determining hydrocarbon properties of aformation from the received signal.
 11. The logging tool of claim 10,further comprising: a communication device that connects the processingdevice to the computer system.
 12. The logging tool of claim 9, whereinthe first signal is an n-pole signal.
 13. The logging tool of claim 12,wherein the n-pole signal is from the group consisting essentially of amonopole signal, dipole signal, quadrupole signal, and hexapole signal.14. The logging tool of claim 9, wherein the first signal's amplitudesand time delays are adjusted if the tool is not centered in the boreholeor the borehole is not circular.
 15. The logging tool of claim 9,wherein the first signal's amplitudes and time delays are adjusted ifthe sources are not matched or the receivers are not balanced.
 16. Thelogging tool of claim 9, wherein the logging tool couples to a drillingdevice that drills the borehole as the logging tool generates theacoustic signal.
 17. A logging tool to generate an acoustic signal witha single mode of propagation along walls of a borehole, comprising: oneor more sources capable of generating a first signal; one or morereceivers capable of receiving the first signal traveling along theborehole walls; and a computer system that couples to the sources andreceivers, said computer system capable of adjusting the first signal'samplitudes and time delays to produce a second signal if the firstsignal traveling along the borehole walls does not have a single mode ofpropagation, the one or more sources generating the second signal. 18.The logging tool of claim 17, further comprising: a processing devicethat couples to the sources and receivers; and a communication devicethat connects the processing device to the computer system.
 19. Thelogging tool of claim 17, wherein the first signal is an n-pole signal.20. The logging tool of claim 19, wherein the n-pole signal is from thegroup consisting essentially of a monopole signal, dipole signal,quadrupole signal, and hexapole signal.
 21. The logging tool of claim17, wherein the logging tool couples to a drilling device that drillsthe borehole as the logging tool generates the acoustic signal.
 22. Amachine-readable medium that provides instructions, which when executedby a machine, cause said machine to perform operations for generating anacoustic signal with a single mode of propagation along borehole wallscomprising: adjusting a first signal's amplitudes and time delays toproduce a second signal if the first signal traveling along boreholewalls does not have a single mode of propagation; generating the secondsignal from one or more tool sources; receiving the second signal at oneor more receivers; and modifying the second signal's amplitudes and timedelays if the second signal traveling along the borehole walls does nothave the single mode of propagation.
 23. The machine-readable medium ofclaim 22, further comprising: determining if the tool is in center ofthe borehole and the borehole is circular; and generating an n-polesignal from the one or more tool sources if the first signal travelingalong borehole walls has a single mode of propagation.
 24. Themachine-readable medium of claim 23, wherein amplitudes and time delaysof the first signal are adjusted if the tool is not centered in theborehole or the borehole is not circular.
 25. The machine-readablemedium of claim 23, wherein amplitudes and time delays of the firstsignal are adjusted if the sources are not matched or the receivers arenot balanced.
 26. The machine-readable medium of claim 23, wherein then-pole signal is from the group consisting essentially of a monopolesignal, dipole signal, quadrupole signal, and hexapole signal.
 27. Themachine-readable medium of claim 23, wherein determining if the tool isin the center of the borehole and the borehole is circular comprisescalculating position of the tool in the borehole and shape of theborehole from signals received at the one or more receivers.
 28. Themachine-readable medium of claim 23, wherein the tool couples to adrilling device that drills the borehole as the tool generates thesignal with a signal mode of propagation along the borehole walls. 29.The machine-readable medium of claim 22, wherein determining time delaysand amplitudes of the signals includes determining velocity of thesignal in the borehole.
 30. (canceled)